Apparatus and method for well completion

ABSTRACT

A flow back process usable on a well during a drilling operation includes the steps of flowing the commingled well fluids and solids into a surface-mounted flow back system under wellbore pressure. Alternatively, a flow back process includes the steps of connecting a surface-mounted flow back system to the well while the well is in an underbalanced condition. The operation of sequentially drilling through each of a plurality of isolation plugs is then initiated while flowing the well fluids and plug fragments into a surface-mounted flow back system. In yet another aspect, a large particle filter includes a filter section, a monitoring assembly, a bypass system and a purge assembly. The large particle filter can be connected to a Christmas tree and used to remove plug fragments from commingled flow leaving the well during a drilling operation.

RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application No. 60/615,274, entitled Apparatus and Method for Well Completion, filed Oct. 1, 2004, the disclosure of which is incorporated herein.

FIELD OF THE INVENTION

The present invention is generally related to the completion or cleanup of oil and gas wells, and more particularly to an apparatus and method for maximizing the recovery of saleable product during completion or cleanup.

BACKGROUND OF THE INVENTION

Well treatment or stimulation operations often include the installation of isolation plugs that separate adjacent zones within a wellbore. In a hydraulic fracturing operation or “frac job,” for example, multiple plugs may be installed so that multiple zones can be directly and distinctly affected by the injection of pressured fluid under controlled conditions. The use of multi-stage hydraulic fracturing techniques, and hence the use of isolation plugs, has dramatically increased in many locations in response to environmental regulations that limit the surface footprint available to hydraulic fracturing equipment.

At the close of the multi-stage hydraulic fracturing operation, completion and cleanup operations must be performed before the well can be brought online. As part of these processes, the isolation plugs are destroyed or removed, in most cases by drilling through the plugs. While effective at destroying the plugs, the process of drilling through the plugs creates large fragments that are known to damage surface-mounted equipment. Accordingly, the fragments from the plugs must be extracted from well effluent before the commingled flow of solids, liquids and gases is allowed to enter downstream gathering or processing systems. Failure to remove these large particulate solids can cause blockages and damage to downstream components.

In the past, operators have kept the wellbore closed or in a “loaded,” overbalanced condition while the isolation plugs are removed. After the isolation plugs have been drilled out, air is injected into the wellbore to remove the commingled fluid of liquids, gases and large solid particles. In the past, the commingled flow was directed into earthen pits and the associated gas was flared or vented to the atmosphere. The well remained offline until all of the large solids were totally flowed out of the well. This process is time consuming and wasteful. Furthermore, with increased environmental regulation, it has become undesirable to vent or flare the gas produced during the cleanup process. Accordingly, there is a need for a faster, more profitable and more environmentally friendly process for conducting the completion and cleanup stages following a multi-stage hydraulic fracturing operation.

SUMMARY OF THE INVENTION

In a presently preferred embodiment, the present invention includes a flow back process usable on a well following a multi-stage hydraulic fracturing operation, in which at least one plug is installed to isolate separate zones within the well. The process preferably includes the steps of destroying the plug without first loading the well and flowing the plug fragments and well fluids into a surface-mounted flow back system while the plug is being destroyed. The process further includes the steps of removing solid particles from the well fluids with the surface-mounted flow back system, separating gaseous components of the well fluids from liquid components with the surface-mounted flow back system and directing the gaseous components to gas sales lines or storage facilities.

In an alternate embodiment, the present invention includes a flow back process usable on a well during a drilling operation. The flow back process preferably includes the steps of connecting a surface-mounted flow back system to the well while the well is maintained in an underbalanced condition. The flow back process further includes the steps of conducting the drilling operation while at the same time flowing the commingled well fluids and solid particles into the surface-mounted flow back system. The solid particles are removed from the well fluids with a large particle filter within the surface-mounted flow back system and the gaseous components of the well fluids are separated from the liquid components. The gaseous components are then directed to gas sales lines or storage facilities.

In another aspect, the present invention includes a large particle filter that is connectable to the Christmas tree of a petroleum well. The large particle filter preferably includes a filter section, a monitoring assembly, a bypass system and a purge assembly. The large particle filter can be used to remove plug fragments from commingled flow leaving the well during a drilling operation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a process flowchart of a well flow back system constructed in accordance with a preferred embodiment of the present invention.

FIG. 2 is a top view, in partial cutaway, of the plug catcher of the well flow back system of FIG. 1.

FIG. 3 is a process flowchart of a well flow back system constructed in accordance with an alternate embodiment of the present invention.

FIG. 4 is a flow diagram for a method for conducting a flow back process following a multi-stage hydraulic fracturing operation in accordance with a presently preferred embodiment.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

The presently preferred embodiment includes a flow back procedure that maximizes the recovery of saleable oil and gas during the completion phase of a drilling operation. The preferred flow back procedure permits the capture and processing of gas and liquid hydrocarbons from the very earliest stages of completion using a closed-loop system. Once processed, the flow back procedure delivers the saleable hydrocarbons to sales lines, thereby avoiding flaring, venting, waste, and associated environmental problems. At the same time, the customer is receiving revenue that offsets part of the completion, well testing, and start-up costs. The flow back procedure enables the producer to achieve sales line quality specifications starting from the flow back, and on through the well cleanup, testing, and startup phases.

Unlike prior art practices, in which the well is not allowed to flow during while drilling operations are conducted on the well, the present flow back methods involve flowing the mixture of solids, liquids and gases under wellbore pressure through a large particle filter located on the surface as the drilling operation is conducted. As the commingled well effluent passes through the large particle filter, large solids are removed from the commingled flow and the filtered effluent is conditioned for handling by downstream equipment.

In a first preferred embodiment, the flow back procedure is preferably conducted through use of a flow back system 100, diagrammatically demonstrated in FIG. 1. The flow back system 100 preferably includes a Christmas tree 102, a large particle filter 104, a hydraulically operated choke manifold 106, a manually operated choke manifold 107, one or more sand separators 108, a 3-phase production separator 110, a gas sales line 112, a liquid sales line 114 and a waste disposal tank 116. It will be understood that additional components can be added to the flow back system 100.

The Christmas tree 102 is preferably equipped with a blowout preventer (“BOP”), flow cross with double wing valves and a coiled tubing or snubbing blowout preventer. The Christmas tree 102 is used to control the flow of filtered effluent out of the well. The Christmas tree 102 and additional valves and safety devices can be utilized to shut-in the well. They are positive-open/positive-closed valves and safety shut-in devices. During setup, a line from the Christmas tree 102 is connected to the large particle filter 104. The large particle filter 104 is preferably configured to extract the large particles (plug fragments, etc.) utilizing a filter with a sufficient number and size of openings to permit the remaining commingled flow to pass.

For the purposes of the disclosure herein, the term “commingled flow,” refers to well effluent that may include solids (plug fragments, sand, etc.), liquids and gas, produced from the subsurface production zones that flows up the well tubing to the Christmas tree 102. The term “filtered effluent” refers to the effluent from the large particle filter 104, from which large particles have been extracted. The terms “saleable gas,” “saleable liquids” and “disposable liquids” refer to the output of the 3-phase production separator 110. “Saleable hydrocarbons” refers to both saleable liquids and saleable gas.

In the first preferred embodiment, the large particle filter 104 is configured as a “plug-catcher” 105 that is well suited for high-pressure applications. Turning to FIG. 2, shown therein is a top plan view, in partial cutaway, of a particularly preferred embodiment of the plug catcher 105. In the presently preferred embodiment, the plug catcher 105 includes four primary assemblies; a filter section 118, a bypass system 120, a monitoring assembly 122 and a purge assembly 124. The filter section 118 preferably includes a first spool 126, a second spool 128 and a filter component 130. In the preferred embodiment, the filter component 130 is configured as a longitudinally oriented pup joint (P110 grade) concentrically housed within the second spool 128. The filter component 130 preferably includes one or more slots or holes 131 that allow fluids to enter the filter component 130 from the annular space between the filter component 130 and the second spool 128. The slots or holes 131 are preferably sized to prevent solid particles of a selected threshold from entering the filter component 130. The filtered effluent, from which large particles have been extracted, are then conducted from the plug catcher 105 to downstream equipment.

In a particularly preferred embodiment, the filter component 130 is configured for threaded engagement with one or both of the ends of the second spool 128 to permit facilitated installation and removal of the filter component 130. Although a single filter component 130 is shown in FIG. 2, it will be understood that additional filter components could be used to further refine the fluids passing through the plug catcher 105. For example, it may be desirable to port the fluid leaving the filter component 130 to a third spool (not shown) that houses a second filter component. Additionally, filter screens can be installed within the second spool 128 in addition to, in place of, or within filter component 130 to remove solid particles from the fluid stream.

The monitoring assembly 122 is configured to provide an operator or control system with real-time information regarding the performance of the large particle filter 104. In the presently preferred embodiment, the monitoring assembly 122 is connected to the first spool 126 and includes a first valve 132, an upstream pressure transducer 134, bleeder valves 136, a second valve 137 and a downstream pressure transducer 139. In a particularly preferred embodiment, the first and second valves 132, 137 and bleeder valves 136 are manually operated “plug” valves.

In normal operation, the first valve 132 is held in an “open” position and the second valve 136 is held in a “closed” position. Accordingly, the upstream pressure transducer 134 is placed in fluid communication with the production stream passing through the filter section 118. The upstream pressure transducer 134 preferably provides a signal representative of the fluid pressure in the filter section 118. The downstream pressure transducer 139 provides a signal representative of the pressure of the filtered effluent leaving the plug catcher 105. The pressure measured in the filter section 118 can be compared with the pressure of the filtered effluent measured by the downstream pressure transducer 139 to determine a pressure drop across the filter section 118.

The bypass system 120 preferably includes an upstream bypass valve 138, an upstream diverter valve 140, a downstream bypass valve 142, a bypass line 144 and a downstream cutoff valve 146. In the presently preferred embodiment the upstream diverter valve 140 is a remotely operated hydraulic valve. The upstream diverter valve 140 is preferably sized to permit the flow of particulate solids into the filter section 118. The upstream bypass valve 138 and downstream bypass valve 142 are preferably manually operated plug valves. The bypass system 120 can be used to direct the production fluid around the filter section 118 without interrupting the operation of the flow back system 100.

The purge assembly 124 preferably includes a first purge valve 148 and a second purge valve 150. The first and second purge valves 148, 150 are preferably sized to permit the flow of commingled fluids with large particulate solids. In a particularly preferred embodiment, the second purge valve 150 is a remotely operated hydraulic valve. In normal operation, the first purge valve 148 is held in an “open” position while the second purge valve 150 is held in a “closed” position.

The information provided by the monitoring assembly 122 can be used to optimize the performance of the plug catcher 105 using the purge assembly 124. An elevated pressure drop across the plug catcher 105 can indicate that the filter section 118 is clogging with solid material extracted from the production stream. To increase flow through the plug catcher 105, the filter section 118 can be flushed using the purge assembly 124.

To initiate a flushing, or backwash, operation in accordance with a preferred embodiment, the operator (or control system) closes upstream diverter valve 140 and opens second purge valve 150. The pressure gradient between the hydraulic choke manifold 106 and the disposal tank 116 causes downstream fluid to backflow through the filter component 130, dislodging solid material trapped in the filter section 118. Once dislodged, the solids are carried out of the plug catcher 105 through the second spool 128, first spool 126 and purge assembly 124. In the preferred embodiment, the solids are transferred to the disposal tank 116. In an alternative embodiment, the backwash procedure is performed using an external fluid source, such as fresh water or compressed air, which is delivered to the plug catcher 105 under pressure. The external fluid source can be connected to the bypass system 120 or directly to the filter section 118.

Once the flushing procedure has been completed, the operator manipulates the various valves on the plug catcher 105 to redirect the flow through the filter section 118. In some cases, it may be necessary to remove the filter component 130 for repair or replacement. To remove the filter component 130, the filter section 118 must be isolated from the high-pressure commingled flow. In an alternative embodiment, an additional valve can be placed between the filter section 118 and the bypass system 120 so that the filter section 118 can be isolated and disassembled without shutting down the flow back system 100.

Turning now to FIG. 3, in yet another alternative embodiment, two or more plug catchers 105 a, 105 b are used in a parallel configuration. In this embodiment, selector valves 152, 154 are used to control the flow of commingled well effluent to the plug catchers 105 a, 105 b. The plug catchers 105 a, 105 b can be used simultaneously or separately. The use of two or more plug catchers 105 a, 105 b enables the operator to bring one of the plug catchers 105 offline for maintenance of purging without interrupting the operation of the flow back system 100 by diverting the production stream to the second plug catcher 105 and downstream equipment. Although only two plug catchers 105 a, 105 b are shown in FIG. 3, it will be appreciated that the use of additional plug catchers 105 is within the scope of this embodiment. It will be further noted that, in certain applications, the two or more plug catchers 105 can be connected in a serial relationship.

Now also referring back to FIG. 1, a primary line is connected between the large particle filter 104 and the hydraulic choke manifold 106. The commingled flow leaving the Christmas tree 102 and the filtered effluent leaving the large particle filter 104 are typically at an elevated wellbore pressure. The hydraulic choke manifold 106 is used to control the flow rate and reduce the pressure to a level that does not exceed the working pressure and flow capacity of the downstream equipment. In the preferred embodiment, the hydraulic choke manifold 106 is the first choke manifold in the flow back system 100 and includes an assembly of chokes, valves, and interconnecting piping. At least some of the chokes and valves are preferably hydraulically operated. Preferably, the choke manifold 106 is also connected to the disposal tank 116. In an alternative embodiment, the disposal tank 116 is replaced with an earthen pit.

The hydraulic choke manifold 106 is connected to a manually operated choke manifold 107 and to the one or more sand separators 108 with a primary line. In certain applications, the manual choke manifold 107 may replace, or be placed upstream, of the hydraulic choke manifold 106. The sand separators 108 knock out, or separate, the liquids/gas from most of the remaining solids in the produced fluid. Periodically, the sand and other solids are discharged from the sand separators 108 through a secondary line to a disposal tank 116. The sand separators 108 use baffles and gravity segregation to remove the solids. The sand separators 108 are preferably sized to allow adequate retention time to facilitate gravity separation of solid particles from the liquid and gas phases.

The remaining filtered effluent then pass from the sand separators 108 to the 3-phase production separator 110. The 3-phase production separator 110 uses a variety of internal components (baffles, weirs, etc.) to separate the water (disposable liquid), oil/condensate (saleable liquid), and natural gas (saleable gas). The 3-phase separator 110 is also preferably sized to allow adequate retention time to facilitate gravity separation of the liquid phases. Level control valves divert the oil/condensate to the line going to the liquids sales line 114 and the water is sent through a secondary line to a disposal tank 116. The gas exits from the top of the separator and goes through an interconnecting line to the gas sales line 112. Depending on the production flow rate and constituent percentages, one or more 3-phase production separators 110 may be used. In certain applications, it may be desirable to consolidate the delivery of the saleable hydrocarbons to storage or downstream equipment in a single line.

It will be understood that the sand separators 108 and the 3-phase production separator can be optionally combined as a single 4-phase separator. The flow back system 100 may also include meters, recorders, and other monitoring devices. These components can be utilized to measure and record the oil/condensate, gas, and water production rates and pressure (not shown). Sample ports are provided to fill sample bottles that are then taken to a laboratory for testing.

The preferred embodiment of the flow back system 100 is well suited for use in high-pressure environments, but may be inefficient or unnecessary in lower pressure applications. In an alternate embodiment, a sand separator (not separately shown) is used as the large particle filter 104 instead of the plug catcher 105. The sand separator can be connected directly to the Christmas tree 102 and used to trap plug fragments or other solid particle during the drilling operation. In this alternate embodiment, the one or more sand separators 108 are not necessary and the output from the manual choke manifold 107 can be conducted directly to the 3-phase separator 110. Like the plug catcher 105, the sand separator can be purged by “dumping” the captured material to the disposal tank 116, as trapped solids increase the resistance to flow through the sand separator. The construction and use of sand separators is well known in the art.

In a preferred embodiment, the flow back system 100 is used to maximize the recovery of saleable hydrocarbons as one or more isolation plugs are drilled out following a multi-stage treatment operation. It will be understood, however, that the flow back system 100 and associated methods of operation will also find utility in other drilling operations, such as, for example, the initial drilling of coal bed methane (“CBM”) wells. As CBM wells are drilled, large chunks of coal or other debris may be forced to the surface if the well is held in an underbalanced condition during the drilling operation to enable the capture of saleable hydrocarbons as the well is drilled.

Turning to FIG. 3, shown therein is a process flow diagram for a flow back process 200 conducted in accordance with a presently preferred embodiment. At step 202, the flow back system 100 is connected to the well. Next, at step 204, the drilling process begins and the production of the commingled well fluids is concurrently initiated. Significantly, unlike prior art flow back procedures, in which the well is loaded or closed during the drilling operation, production under the presently preferred flow back procedure 200 begins while the drilling operation takes place in an underbalanced environment.

The ability to process the commingled flow during the drill out process is enabled through use of a large particle filter. At step 206, large particulate solids, including plug fragments, are extracted from the commingled well effluent. In high-pressure environments, the large particle filter is preferably the plug catcher 105. In lower pressure environments, the plug catcher 105 may be substituted with less robust equipment, such as a sand separator.

Once the large solid particles have been extracted from the commingled flow, the filtered effluent leaving the large particle filter 104, which may include a combination of liquids, gases and smaller particles, is separated into its saleable and disposable constituents at step 208. In the presently preferred embodiment, the sand separator 108 and 3-phase separator 110 cooperatively separate the saleable and disposable constituents of the produced fluid. At step 210, the saleable gas and saleable liquid are delivered to the gas sales line 112 and the liquids sales line 114, respectively. At step 212, the disposable liquid, which may include water, is sent to the disposal tank 116.

It will be appreciated that the flow back process 200 preferably occurs on a continuous basis, in which one or more of the steps outlined above occur simultaneously. For example, once the flow back process 200 has started, saleable gas and liquid are being delivered to sales lines (step 210) as isolation plugs are being drilled through (step 204). While the preferred embodiment of the flow back process 200 has been disclosed in an application following a multi-stage hydraulic fracturing operation, it will be understood that the same flow back process could be used in other applications where the effluent produced during the completion of a well contains large solid particles.

It is clear that the present invention is well adapted to carry out its objectives and attain the ends and advantages mentioned above as well as those inherent therein. While presently preferred embodiments of the invention have been described in varying detail for purposes of disclosure, it will be understood that numerous changes may be made which will readily suggest themselves to those skilled in the art and which are encompassed within the spirit of the invention disclosed herein and in the associated drawings and appended claims. 

1. A flow back process usable on a well following a multi-stage hydraulic fracturing operation, in which at least one plug is installed to isolate separate zones within the well, the process comprising the steps of: destroying the plug; flowing the plug fragments and well fluids into a surface-mounted flow back system while the plug is being destroyed; removing solid particles from the well fluids with the surface-mounted flow back system; separating gaseous components of the well fluids from liquid components with the surface-mounted flow back system; and directing the gaseous components to gas sales lines or storage facilities.
 2. The process of claim 1, wherein the step of destroying the plug comprises drilling out the plug.
 3. The process of claim 1, wherein the step of flowing the plug debris further comprises flowing the plug debris and well contents into a flow back system using downhole pressures.
 4. The process of claim 1, wherein the step of removing solid components from the well contents further comprises conducting the flow of plug debris and well fluids directly from the well to a large particle filter configured to remove solid particles from the filtered effluent.
 5. The process of claim 4, further comprising a step of purging the large particle filter into a disposal tank using downstream fluids in a backflow direction.
 6. The process of claim 5, wherein the step of purging the high-pressure filter is conducted in response to an increased pressure drop across the high-pressure filter.
 7. The process of claim 4, wherein the step of removing the gaseous components of the well fluids from the liquid components of the well fluids further comprises passing the well fluids through a three-phase separator downstream from the high-pressure filter.
 8. The process of claim 7, further comprising the step of sending liquid petroleum products separated in the three-phase separator to a liquids sales line or storage facility.
 9. A large particle filter connectable to the Christmas tree of a petroleum well, the filter comprising: a filter section; a monitoring assembly; a bypass system; and a purge assembly.
 10. The large particle filter of claim 9, wherein the filter section comprises: a first spool; a second spool; and a filter component disposed within the second spool.
 11. The large particle filter of claim 10, wherein the filter is configured as a portion of tubing that includes a series of slots extending therethrough.
 12. The large particle filter of claim 10, wherein the monitoring system is connected to the first spool and wherein the monitoring system further comprises a pressure transducer configured to detect the pressure of the fluid passing through the first spool.
 13. The large particle filter of claim 12, wherein the pressure transducer is configured to transmit a signal representative of the fluid pressure in the first spool.
 14. The large particle filter of claim 9, wherein the bypass system comprises: an upstream bypass valve; an upstream diverter valve; a bypass line; a downstream bypass valve; and a downstream cutoff valve.
 15. A flow back process usable on a well during a drilling operation, the process comprising the steps of: connecting a surface-mounted flow back system to the well, wherein the well is maintained in an underbalanced condition; initiating the drilling operation; flowing the commingled well fluids and solid particles into a surface-mounted flow back system during the drilling operation; removing the solid particles from the well fluids with a large particle filter within the surface-mounted flow back system; separating gaseous components of the well fluids from liquid components with the surface-mounted flow back system; and directing the gaseous components to gas sales lines or storage facilities.
 16. The process of claim 15, further comprising a step of purging the large particle filter into a disposal tank using downstream fluids in a backflow direction.
 17. The process of claim 16, wherein the step of separating the gaseous components of the well fluids from the liquid components of the well fluids further comprises passing the well fluids through a three-phase separator downstream from the large particle filter.
 18. The process of claim 15, wherein the drilling process is conducted to remove one or more isolation plugs used to separate zones within a well following a multi-stage treatment operation.
 19. The process of claim 15, wherein the drilling process is conducted as the initial drilling operation on a coal bed methane well.
 20. A flow back system configured to be connected to a Christmas Tree, the flow back system comprising: a choke manifold; and a plurality of large particle filters, wherein each of the plurality of large particle filters is located between the Christmas Tree and the choke manifold.
 21. The flow back system of claim 20, wherein the plurality of large particle filters are plug catchers.
 22. The flow back system of claim 21, wherein the plug catchers are configured in a parallel relationship.
 23. The flow back system of claim 21, wherein the plug catchers are configured in a serial relationship. 